<PAGE> 1
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
------------
FORM 10-Q
------------
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1999
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER: 1-9743
ENRON OIL & GAS COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 47-0684736
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
1400 SMITH STREET, HOUSTON, TEXAS 77002-7369
(Address of principal executive offices) (zip code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 713-853-6161
------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ].
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of July 26, 1999.
<TABLE>
<CAPTION>
TITLE OF EACH CLASS NUMBER OF SHARES
------------------- ----------------
<S> <C>
Common Stock, $.01 par value 153,914,790 shares
</TABLE>
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-1-
<PAGE> 2
ENRON OIL & GAS COMPANY
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE NO.
--------
<S> <C> <C>
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Consolidated Statements of Income - Three Months Ended June 30, 1999 and 1998
and Six Months Ended June 30, 1999 and 1998.............................................................. 3
Consolidated Balance Sheets - June 30, 1999 and December 31, 1998............................................ 4
Consolidated Statements of Cash Flows - Six Months Ended June 30, 1999 and 1998.............................. 5
Notes to Consolidated Financial Statements................................................................... 6
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................ 10
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings................................................................................ 21
ITEM 4. Submission of Matters to a Vote of Security Holders.............................................. 21
ITEM 6. Exhibits and Reports on Form 8-K................................................................. 21
</TABLE>
-2-
<PAGE> 3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Share Amounts)
(Unaudited)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas
Trade $ 127,508 $ 135,113 $ 244,775 $ 264,680
Associated Companies 28,251 15,510 41,094 38,533
Crude Oil, Condensate and Natural Gas Liquids
Trade 36,740 27,277 63,257 57,514
Associated Companies 223 2,815 1,259 5,554
Gains (Losses) on Sales of Reserves and Related Assets and Other, Net (5,527) 2,592 (4,236) 16,857
--------- --------- --------- ---------
TOTAL 187,195 183,307 346,149 383,138
OPERATING EXPENSES
Lease and Well 23,538 22,857 47,607 47,766
Exploration Costs 10,302 16,600 27,091 33,998
Dry Hole Costs 2,130 2,281 2,475 10,162
Impairment of Unproved Oil and Gas Properties 7,984 7,355 15,987 15,703
Depreciation, Depletion and Amortization 88,781 73,071 170,803 145,032
General and Administrative 26,384 15,204 50,019 31,758
Taxes Other Than Income 12,381 13,270 26,076 27,764
--------- --------- --------- ---------
TOTAL 171,500 150,638 340,058 312,183
--------- --------- --------- ---------
OPERATING INCOME 15,695 32,669 6,091 70,955
OTHER INCOME (EXPENSE), NET 31,352 (73) 58,290 (1,043)
--------- --------- --------- ---------
INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES 47,047 32,596 64,381 69,912
INTEREST EXPENSE, NET 14,774 10,423 29,041 19,533
--------- --------- --------- ---------
INCOME BEFORE INCOME TAXES 32,273 22,173 35,340 50,379
INCOME TAX PROVISION 11,635 8,916 9,636 10,117
--------- --------- --------- ---------
NET INCOME $ 20,638 $ 13,257 $ 25,704 $ 40,262
========= ========= ========= =========
NET INCOME PER SHARE OF COMMON STOCK
Basic $ 0.13 $ 0.09 $ 0.17 $ 0.26
========= ========= ========= =========
Diluted $ 0.13 $ 0.09 $ 0.17 $ 0.26
========= ========= ========= =========
AVERAGE NUMBER OF COMMON SHARES
Basic 153,825 154,857 153,779 154,797
========= ========= ========= =========
Diluted 155,271 155,770 154,943 155,646
========= ========= ========= =========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
-3-
<PAGE> 4
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
ENRON OIL & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(In Thousands)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
----------- -----------
(UNAUDITED)
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 11,411 $ 6,303
Accounts Receivable
Trade 159,469 176,608
Associated Companies 12,795 16,980
Inventories 35,175 39,581
Other 6,420 6,878
----------- -----------
TOTAL 225,270 246,350
OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS METHOD) 4,965,113 4,814,425
Less: Accumulated Depreciation, Depletion and Amortization (2,298,265) (2,138,062)
----------- -----------
Net Oil and Gas Properties 2,666,848 2,676,363
OTHER ASSETS 69,928 95,382
----------- -----------
TOTAL ASSETS $ 2,962,046 $ 3,018,095
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable
Trade $ 119,664 $ 159,690
Associated Companies 41,014 46,597
Accrued Taxes Payable 16,465 20,087
Dividends Payable 4,736 4,710
Other 17,608 31,550
----------- -----------
TOTAL 199,487 262,634
LONG-TERM DEBT
Trade 1,073,883 942,779
Affiliate 66,000 200,000
OTHER LIABILITIES
Trade 19,004 21,516
Associated Companies 26,085 46,327
DEFERRED INCOME TAXES 265,444 260,337
DEFERRED REVENUE 2,099 4,198
SHAREHOLDERS' EQUITY
Common Stock, $.01 Par, 320,000,000 Shares Authorized and
160,000,000 Shares Issued 201,600 201,600
Additional Paid In Capital 401,042 401,524
Unearned Compensation (4,183) (4,900)
Cumulative Foreign Currency Translation Adjustment (26,124) (35,848)
Retained Earnings 854,846 838,371
Common Stock Held in Treasury, 6,104,863 shares at
June 30, 1999 and 6,276,156 shares at December 31, 1998 (117,137) (120,443)
----------- -----------
TOTAL SHAREHOLDERS' EQUITY 1,310,044 1,280,304
----------- -----------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 2,962,046 $ 3,018,095
=========== ===========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
-4-
<PAGE> 5
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
----------------------
1999 1998
--------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income to Net Operating Cash Inflows:
Net Income $ 25,704 $ 40,262
Items Not Requiring Cash
Depreciation, Depletion and Amortization 170,803 145,032
Impairment of Unproved Oil and Gas Properties 15,987 15,703
Deferred Income Taxes 4,317 11,980
Other, Net 410 3,520
Exploration Costs 27,091 33,998
Dry Hole Costs 2,475 10,162
Losses (Gains) on Sales of Reserves and Related Assets and Other, Net 6,723 (13,447)
Gains on Sales of Other Assets (59,647) --
Other, Net (13,322) (4,100)
Changes in Components of Working Capital and Other Liabilities
Accounts Receivable 19,226 40,213
Inventories 4,406 (2,776)
Accounts Payable (46,285) (37,391)
Accrued Taxes Payable (3,622) (14,208)
Other Liabilities (3,909) (23,196)
Other, Net (11,234) (5,034)
Amortization of Deferred Revenue -- (21,494)
Changes in Components of Working Capital Associated with
Investing and Financing Activities 16,019 14,665
--------- ---------
NET OPERATING CASH INFLOWS 155,142 193,889
INVESTING CASH FLOWS
Additions to Oil and Gas Properties (179,749) (270,684)
Exploration Costs (27,091) (33,998)
Dry Hole Costs (2,475) (10,162)
Proceeds from Sales of Reserves and Related Assets 2,756 54,688
Proceeds from Sales of Other Assets 83,015 --
Changes in Components of Working Capital Associated with
Investing Activities (15,811) (14,518)
Other, Net (1,201) (5,604)
--------- ---------
NET INVESTING CASH OUTFLOWS (140,556) (280,278)
FINANCING CASH FLOWS
Long-Term Debt
Trade 131,104 302,085
Affiliate (134,000) (192,500)
Dividends Paid (9,203) (9,268)
Treasury Stock Purchased -- (7,969)
Proceeds from Sales of Treasury Stock 2,949 2,222
Other, Net (328) (3,943)
--------- ---------
NET FINANCING CASH INFLOWS (OUTFLOWS) (9,478) 90,627
--------- ---------
INCREASE IN CASH AND CASH EQUIVALENTS 5,108 4,238
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 6,303 9,330
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 11,411 $ 13,568
========= =========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
-5-
<PAGE> 6
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. The consolidated financial statements of Enron Oil & Gas Company and
subsidiaries (the "Company") included herein have been prepared by
management without audit pursuant to the rules and regulations of the
Securities and Exchange Commission. Accordingly, they reflect all
adjustments which are, in the opinion of management, necessary for a fair
presentation of the financial results for the interim periods. Certain
information and notes normally included in financial statements prepared in
accordance with generally accepted accounting principles have been
condensed or omitted pursuant to such rules and regulations. However,
management believes that the disclosures are adequate to make the
information presented not misleading. These consolidated financial
statements should be read in conjunction with the consolidated financial
statements and the notes thereto included in the Company's Annual Report on
Form 10-K for the year ended December 31, 1998.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
Certain reclassifications have been made to prior period financial
statements to conform with the current presentation.
As more fully discussed in Notes 1 and 14 to the consolidated financial
statements included in the Company's 1998 Annual Report on Form 10-K, the
Company engages in price risk management activities from time to time
primarily for non-trading and to a lesser extent for trading purposes.
Derivative financial instruments (primarily price swaps and costless
collars) are utilized for non-trading purposes to hedge the impact of
market fluctuations on natural gas and crude oil market prices. Hedge
accounting is utilized in non-trading activities when there is a high
degree of correlation between price movements in the derivative and the
item designated as being hedged. Gains and losses on derivative financial
instruments used for hedging purposes are recognized as revenue in the same
period as the hedged item. Gains and losses on hedging instruments that are
closed prior to maturity are deferred in the consolidated balance sheets.
In instances where the anticipated correlation of price movements does not
occur, hedge accounting is terminated and future changes in the value of
the derivative are recognized as gains or losses using the mark-to-market
method of accounting. Derivative and other financial instruments utilized
in connection with trading activities, primarily price swaps and call
options, are accounted for using the mark-to-market method, under which
changes in the market value of outstanding financial instruments are
recognized as gains or losses in the period of change. The cash flow impact
of derivative and other financial instruments used for non-trading and
trading purposes is reflected as cash flows from operating activities in
the consolidated statements of cash flows.
2. Natural gas revenues, trade for the three-month and six-month periods ended
June 30, 1999 and 1998, are net of costs of natural gas purchased for sale
related to natural gas marketing activities of $12.5 million, $11.8
million, $20.9 million and $24.3 million, respectively. Natural gas
revenues, associated for the three-month and six-month periods ended June
30, 1999 and 1998, are net of costs of natural gas purchased for sale
related to natural gas marketing activities of $0.3 million, $12.0 million,
$13.4 million and $24.4 million, respectively.
3. The income tax provision for the six-month period ended June 30, 1999 was
calculated using the annual effective rate method. The income tax provision
for the three-month period ended June 30, 1999 was calculated as the
difference between the six-month period ended June 30, 1999 provision and
the three-month period ended March 31, 1999 provision, which was calculated
using the actual effective rate for that period. The income tax provision
for the prior year periods was calculated using the annual effective rate
method.
Income tax provision for the three-month and six-month periods ended June
30, 1999 and 1998 includes tax benefits of $0.5 million, $2.5 million, $3.2
million and $3.8 million, respectively, related to tight gas sand federal
income tax credit utilization. Additionally, the income tax provision for
the three-month and six-month periods ended June 30, 1999 includes a
benefit of $4.4 million from the anticipated disposition of certain
international assets and other benefits of $0.4 million from the resolution
of certain domestic issues. The income tax provision for the six-month
period ended June 30, 1998 includes a benefit of $3.4 million from certain
international costs and other benefits of $5.0 million from the resolution
of certain state and international issues.
4. The difference between the average number of common shares outstanding for
basic and diluted net income per share of common stock is due to the
assumed issuance of approximately 1,446,000, 913,000, 1,164,000 and 849,000
common shares relating to employee stock options in the three-month and
six-month periods ended June 30, 1999 and 1998, respectively.
-6-
<PAGE> 7
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. The Company's total comprehensive income was $26.9 million, $4.1 million,
$35.4 million and $33.3 million for the three-month and six-month periods
ended June 30, 1999 and 1998, respectively. The only adjustment made to net
income in the periods was for a foreign currency translation gain of $6.3
million, loss of $9.2 million, gain of $9.7 million and loss of $7.0
million for the three-month and six-month periods ended June 30, 1999 and
1998, respectively.
6. Selected financial information about operating segments is reported below
for the three-month and six-month periods ended June 30, 1999 and 1998:
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
NET OPERATING REVENUES
United States $ 135,377 $ 132,726 $ 242,269 $ 284,013
Canada 21,086 15,779 37,310 32,710
Trinidad 15,690 16,496 32,689 30,780
India (1) 21,432 18,294 40,265 35,646
China (1) 2 -- 4 --
Other (6,392) 12 (6,388) (11)
--------- --------- --------- ---------
TOTAL $ 187,195 $ 183,307 $ 346,149 $ 383,138
========= ========= ========= =========
OPERATING INCOME (LOSS)
United States $ 1,904 $ 16,755 $ (16,610) $ 42,129
Canada 6,505 2,275 8,847 4,763
Trinidad 9,506 10,469 19,637 18,696
India (1) 12,324 10,277 15,830 19,452
China (1) (2,631) (1,959) (4,998) (3,904)
Other (11,913) (5,148) (16,615) (10,181)
--------- --------- --------- ---------
TOTAL 15,695 32,669 6,091 70,955
RECONCILING ITEMS
Other Income (Expense), Net 31,352 (73) 58,290 (1,043)
Interest Expense, Net 14,774 10,423 29,041 19,533
--------- --------- --------- ---------
INCOME BEFORE INCOME TAXES $ 32,273 $ 22,173 $ 35,340 $ 50,379
========= ========= ========= =========
</TABLE>
- ------------------
(1) See Note 10.
7. As reported in the Company's Annual Report on Form 10-K for the year ended
December 31, 1998, Enron Oil & Gas India Ltd. ("EOGIL"), a wholly-owned
subsidiary of the Company, is a respondent in two public interest lawsuits
filed in the Delhi High Court, India. The first (the "Wadehra Action") was
brought by B. L. Wadehra, an Indian public interest lawyer, against the
Union of India, EOGIL, EOGIL co-participants in the Panna and Mukta fields,
Reliance Industries Limited ("Reliance") and Oil & Natural Gas Corporation
Limited ("ONGC"), and certain other respondents. ONGC is the Indian
national oil company and is wholly-owned by the Union of India. The second
suit (the "CPIL Action") was brought by the Centre for Public Interest
Litigation and the National Alliance of People's Movement against the Union
of India, the Central Bureau of Investigation, ONGC, Reliance and EOGIL.
Petitioners in both the Wadehra Action and the CPIL Action allege various
improprieties in the award of the Panna and Mukta fields to EOGIL, Reliance
and ONGC, and seek the cancellation of the Production Sharing Contract for
the Panna and Mukta fields. The Union of India is vigorously disputing
these allegations. The Company believes that the public competitive bidding
process for the fields was fair and that the award of these fields to
EOGIL, Reliance and ONGC was proper. Following a series of hearings, the
Delhi High Court has entered an order dismissing both lawsuits. The India
Supreme Court has agreed to hear the plaintiffs' appeal of the decision of
the Delhi High Court. Although no assurances can be given, based on
currently available information the Company believes that the ultimate
resolution of these matters will not have a material adverse effect on its
financial condition or results of operations.
-7-
<PAGE> 8
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On July 21, 1999, two stockholders of the Company filed separate lawsuits
purportedly on behalf of the Company against Enron Corp. and the Company's
directors, alleging that Enron Corp. and the Company's directors breached
their fiduciary duties of good faith and loyalty in approving the Share
Exchange described in Note 10 below. The lawsuits seek to temporarily and
permanently enjoin the Share Exchange and seek compensatory damages and
costs and expenses, including reasonable attorneys' and experts' fees. The
Company, Enron Corp. and the Company's directors believe the lawsuits are
without merit and intend to vigorously contest them.
There are various other suits and claims against the Company that have
arisen in the ordinary course of business. However, management does not
believe these suits and claims will individually or in the aggregate have a
material adverse effect on the Company's financial condition or results of
operations. The Company has been named as a potentially responsible party
in certain Comprehensive Environmental Response Compensation and Liability
Act proceedings. However, management does not believe that any potential
assessments resulting from such proceedings will individually or in the
aggregate have a materially adverse effect on the financial condition or
results of operations of the Company.
8. In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133 - "Accounting
for Derivative Instruments and Hedging Activities" effective for fiscal
years beginning after June 15, 1999. In June 1999, the FASB issued SFAS No.
137, which delays the effective date of SFAS No. 133 for one year, to
fiscal years beginning after June 15, 2000. SFAS No. 133, as amended by
SFAS No. 137, cannot be applied retroactively and must be applied to (a)
derivative instruments and (b) certain derivative instruments embedded in
hybrid contracts that were issued, acquired or substantively modified after
a transition date to be selected by the Company of either December 31, 1997
or December 31, 1998.
The statement establishes accounting and reporting standards requiring that
every derivative instrument be recorded in the balance sheet as either an
asset or liability measured at its fair value. The statement requires that
changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the statements of income and requires a
company to formally document, designate and assess the effectiveness of
transactions that receive hedge accounting treatment.
The Company has not yet quantified the impacts of adopting SFAS No. 133 on
its financial statements and has not determined the timing of adoption.
Based on the Company's current level of derivative and hedging activities,
the Company does not expect the impact of adoption to be material.
9. During the first and second quarters of 1999, the Company sold its 3.2
million options to purchase common stock of Enron Corp. having a strike
price of $39.1875 per share. In the first quarter of 1999, the Company sold
1.6 million options at an average price of $24.81 ($64.00 Enron Corp. stock
price equivalent), realizing net proceeds of $40 million and a gain of $28
million pre-tax ($18 million after-tax). Early in the second quarter, the
Company sold the remaining 1.6 million options at an average price of
$27.07 ($66.26 Enron Corp. stock price equivalent), realizing net proceeds
of $43 million and a gain of $32 million pre-tax ($21 million after-tax).
10. On July 20, 1999, the Company and Enron Corp. announced an agreement
whereby the Company will receive 62,270,000 shares of the Company's common
stock out of 82,270,000 shares currently owned by Enron Corp. in exchange
for all the stock of the Company's subsidiary, EOGI-India, Inc. Prior to
the share exchange, the Company will make an indirect capital contribution
of $600,000,000 in cash, plus certain intercompany receivables, to
EOGI-India, Inc. At the time of completion of this transaction, this
subsidiary will own, through subsidiaries, all of the Company's assets and
operations in India and China. The Company expects this transaction to be
tax-free to Enron Corp. and the Company. Some time after the share
exchange, the Company expects to change its corporate name to "EOG
Resources, Inc." and will make appropriate changes to its subsidiaries'
names.
The completion of the Share Exchange Agreement (the "Share Exchange") is
subject to specific conditions and will occur on the later of August 31,
1999 and three days after all conditions have been satisfied or waived. If
prior to August 31, 1999, all conditions to the Share Exchange have been
satisfied or waived, the Company can require that the Share Exchange take
place prior to August 31, 1999. The Company currently expects the Share
Exchange to close on or before August 31, 1999.
-8-
<PAGE> 9
On July 23, 1999, the Company filed a registration statement with the
Securities and Exchange Commission for the public offering of 27,000,000
shares of the Company's common stock. The proceeds will be used to fund a
significant portion of the cash capital contribution (or to repay debt
incurred to fund such capital contribution) in connection with the Share
Exchange.
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONCLUDED)
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As a result of the change to the Company's portfolio of assets subsequent
to the Share Exchange, the Company is currently re-evaluating its overall
business. The Company expects to complete this re-evaluation by the end of
third quarter 1999. As a result of this re-evaluation, some of the
Company's current projects may no longer be deemed central to its business.
In that case, the Company may incur non-cash charges in connection with the
disposition of such projects of up to approximately $75 million, after-tax.
On July 28, 1999, the Company executed a series of new credit agreements
aggregating $1.3 billion (the "Credit Facilities"). At the same time, the
Company cancelled its existing credit facilities totaling $450 million. Of
the $1.3 billion, $500 million will expire in 364 days (the "Interim
Facility"), $400 million is structured as a 364-day revolving credit
facility with a one-year term subsequent to the revolving period and $400
million is structured as a five-year revolving credit facility. The Interim
Facility will be cancelled (or if advances have been made under the Interim
Facility, such advances will be repaid and then the Interim Facility will
be cancelled) when the Company receives the proceeds from the equity
issuance mentioned above. The Credit Facilities contain financial covenants
which may restrict to some extent the Company's ability to incur additional
indebtedness. Management of the Company does not view these convenants as
being materially restrictive given current market conditions.
-9-
<PAGE> 10
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ENRON OIL & GAS COMPANY
The following review of operations for the three-month and six-month
periods ended June 30, 1999 and 1998 should be read in conjunction with the
consolidated financial statements of Enron Oil & Gas Company (the "Company") and
Notes thereto.
RESULTS OF OPERATIONS
Three Months Ended June 30, 1999 vs. Three Months Ended June 30, 1998
The Company generated second quarter net income of $21 million compared to
net income of $13 million for the second quarter of 1998. Net operating revenues
were $187 million as compared to $183 million for the second quarter of 1998.
Following is an explanation of the variances causing this increase.
Wellhead volume and price statistics are summarized below:
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
NATURAL GAS VOLUMES (MMCF PER DAY) (1)
United States 642 624 (2)
Canada 112 98
--------- ---------
North America 754 722
Trinidad 130 132
India (6) 75 53
--------- ---------
TOTAL 959 907
========= =========
AVERAGE NATURAL GAS PRICES ($/MCF) (3)
United States $ 1.99 $ 2.04 (4)
Canada 1.63 1.41
North America Composite 1.93 1.96
Trinidad 1.07 1.08
India (6) 1.95 2.57
COMPOSITE 1.82 1.87
CRUDE OIL/CONDENSATE VOLUMES (MBBL PER DAY) (1)
United States 13.1 12.2
Canada 2.7 2.5
--------- ---------
North America 15.8 14.7
Trinidad 2.3 2.9
India (6) 6.4 4.8
--------- ---------
TOTAL 24.5 22.4
========= =========
AVERAGE CRUDE OIL/CONDENSATE PRICES ($/BBL) (3)
United States $ 16.48 $ 13.10
Canada 14.26 11.47
North America Composite 16.10 12.82
Trinidad 14.46 13.31
India (6) 14.03 13.41
COMPOSITE 15.41 13.01
NATURAL GAS EQUIVALENT VOLUMES (MMCFE PER DAY) (5)
United States 737 713
Canada 135 119
--------- ---------
North America 872 832
Trinidad 144 149
India (6) 113 82
--------- ---------
TOTAL 1,129 1,063
========= =========
TOTAL BCFE (5) DELIVERIES 103 97 (2)
</TABLE>
- -------------
(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Includes 48 MMcf per day delivered under the terms of a volumetric
production payment agreement effective October 1, 1992, as amended.
Delivery obligations were terminated in December 1998.
(3) Dollars per thousand cubic feet or per barrel, as applicable.
(4) Includes an average equivalent wellhead value of $1.57 per Mcf for the
volumes described in note (2), net of transportation costs.
(5) Million cubic feet equivalent per day or billion cubic feet equivalent, as
applicable.
(6) See Note 10 to the Consolidated Financial Statements.
-10-
<PAGE> 11
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
Wellhead revenues increased 7% to $196 million in the second quarter of
1999 compared to $183 million in the second quarter of 1998.
Average wellhead crude oil and condensate prices were approximately 18%
higher than the comparable period in 1998, increasing net operating revenues by
$5 million. Average wellhead natural gas prices were down by 3%, decreasing net
operating revenues by $4 million. Second quarter 1999 wellhead natural gas
deliveries were approximately 6% higher than the comparable period in 1998
increasing net operating revenues by $9 million. Natural gas deliveries in North
America increased 4% from the prior year period primarily due to the third
quarter 1998 acquisition of producing properties in the Gulf of Mexico,
increased deliveries in East Texas and increased natural gas production in the
Blackfoot and Sandhills fields in Canada. Natural gas deliveries in India
increased 42% to 75 MMcf per day due to continuing development activities in the
Tapti and Panna fields. Wellhead crude oil and condensate deliveries were 9%
higher than the prior year period increasing net operating revenues by $3
million. The increase is primarily attributable to a 33% increase in India and a
7% improvement in North America primarily in the West Texas and East Texas
areas.
Gains (losses) on sales of reserves and related assets and other, net
totaled a $5.5 million loss in the second quarter of 1999 compared to a $2.6
million gain in the comparable period of 1998. Included in 1999 was a $6.4
million loss related to the anticipated dispostion of certain international
assets.
Operating expenses of $172 million for the second quarter of 1999 were
approximately $21 million higher than the second quarter of 1998. Depreciation,
depletion and amortization ("DD&A") expense increased approximately $16 million
compared to the prior year period, primarily reflecting a non-recurring charge
of $7.8 million recorded pursuant to a change in strategy related to the pursuit
of certain offshore operations by the Company, increased worldwide production
volumes and a higher per-unit rate in North America. General and administrative
("G&A") expense was $11 million higher than the prior year period primarily due
to non-recurring costs of $8.9 million related to the potential sale of the
Company and personnel expenses. Exploration and dry hole costs were $6 million
lower than the second quarter of 1998 primarily due to decreased exploratory
drilling and other exploration activities.
The per unit operating costs of the Company for lease and well, DD&A, G&A,
interest expense, and taxes other than income averaged $1.61 per Mcfe during the
second quarter of 1999 compared to $1.39 per Mcfe during the second quarter of
1998. The increase is primarily due to a higher per unit rate of interest, G&A
and DD&A expenses, partially offset by a lower per unit rate of lease and well
expense and taxes other than income. Excluding the previously mentioned
non-recurring charges of $7.8 million in DD&A and $8.9 million in G&A, the per
unit operating costs of the Company were $1.45 per Mcfe in the second quarter of
1999.
Interest expense, net increased $4 million as compared to the second
quarter of 1998 reflecting a higher level of long-term debt due to expanded
worldwide operations.
Other income (expense), net for the second quarter of 1999 included a $32
million pre-tax gain on the sale of 1.6 million of the Company's options to
purchase Enron Corp. common stock (See Note 9 to the Consolidated Financial
Statements).
Income tax provision increased $3 million as compared to the second quarter
of 1998 primarily due to higher pre-tax income partially offset by tax benefits
related to the anticipated disposition of certain international assets.
Additionally, the income tax provision for the six-month period ended June 30,
1999 was calculated using the annual effective rate method. The income tax
provision for the three-month period ended June 30, 1999 was calculated as the
difference between the six-month period ended June 30, 1999 provision and the
three-month period ended March 31, 1999 provision, which was calculated using
the actual effective rate for that period. The income tax provision for the
prior year periods was calculated using the annual effective rate method.
-11-
<PAGE> 12
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS- (CONTINUED)
ENRON OIL & GAS COMPANY
Six Months Ended June 30, 1999 vs. Six Months Ended June 30, 1998
In the first half of 1999, the Company generated net income of $26 million
compared to net income of $40 million for the first half of 1998. Net operating
revenues for the first half of 1999 were $346 million as compared to $383
million for the first half of 1998.
Wellhead volume and price statistics are as follows:
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
NATURAL GAS VOLUMES (MMCF PER DAY)
United States 659 634 (1)
Canada 108 99
--------- ---------
North America 767 733
Trinidad 141 121
India (3) 74 50
--------- ---------
TOTAL 982 904
========= =========
AVERAGE NATURAL GAS PRICES ($/MCF)
United States $ 1.80 $ 2.03 (2)
Canada 1.51 1.40
North America Composite 1.76 1.94
Trinidad 1.07 1.08
India (3) 1.95 2.63
COMPOSITE 1.67 1.87
CRUDE OIL/CONDENSATE VOLUMES (MBBL PER DAY)
United States 13.1 12.4
Canada 2.7 2.6
--------- ---------
North America 15.8 15.0
Trinidad 2.6 2.8
India (3) 6.7 4.5
--------- ---------
TOTAL 25.1 22.3
========= =========
AVERAGE CRUDE OIL/CONDENSATE PRICES ($/BBL)
United States $ 13.91 $ 13.90
Canada 13.03 12.77
North America Composite 13.76 13.70
Trinidad 11.83 13.66
India (3) 11.80 14.31
COMPOSITE 13.04 13.82
NATURAL GAS EQUIVALENT VOLUMES (MMCFE PER DAY)
United States 754 724 (1)
Canada 129 121
--------- ---------
North America 883 845
Trinidad 156 138
India (3) 114 78
--------- ---------
TOTAL 1,153 1,061
========= =========
TOTAL BCFE DELIVERIES 209 192
</TABLE>
- ------------------
(1) Includes 48 MMcf per day delivered under the terms of a volumetric
production payment agreement effective October 1, 1992, as amended.
Delivery obligations were terminated in December 1998.
(2) Includes an average equivalent wellhead value of $1.59 per Mcf for the
volumes described in note (1), net of transportation costs.
(3) See Note 10 to the Consolidated Financial Statements.
-12-
<PAGE> 13
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
Wellhead revenues decreased approximately 2% to $361 million in the first
half of 1999 compared to $367 million in the first half of 1998.
Average wellhead natural gas prices for the first half of 1999 were
approximately 11% lower than the comparable period of 1998 reducing net
operating revenues by approximately $34 million. Average wellhead crude oil and
condensate prices were down by 6%, decreasing net operating revenues by $4
million. First half 1999 wellhead natural gas deliveries were approximately 9%
higher than the comparable period in 1998 increasing net operating revenues by
$26 million. Natural gas deliveries in North America increased 5% from the prior
year period primarily due to the third quarter 1998 acquisition of producing
properties in the Gulf of Mexico and increased deliveries in East Texas. Natural
gas deliveries in India increased 48% to 74 MMcf per day due to continuing
development activities in the Tapti and Panna fields. Natural gas deliveries in
Trinidad were 17% higher due primarily to additional gas balancing volumes
related to a field allocation agreement. Wellhead crude oil and condensate
deliveries were 13% higher than the prior year period increasing net operating
revenues by $7 million, primarily attributable to a 49% increase in India.
Deliveries from the Panna and Mukta fields increased to 6.7 MBbl per day
compared to 4.5 MBbl per day in the prior year period. Deliveries of crude oil
and condensate in North America were up approximately 5% primarily in the West
Texas and South Texas areas.
Other marketing activities associated with sales and purchases of natural
gas, natural gas and crude oil price hedging and trading transactions, and 1998
margins related to the volumetric production payment decreased net operating
revenues by $11 million compared to a revenue decrease of less than one million
in the first half of 1998. This variance was primarily due to a $4 million
revenue decrease in 1999 from natural gas hedging contracts closed in prior
periods, (See Note 14 to the Consolidated Financial Statements in the Company's
1998 Annual Report on Form 10-K) as compared to a $4 million revenue increase
related to natural gas hedging and trading activities in the first half of 1998.
Gains (losses) on sales of reserves and related assets and other, net
totaled a loss of $4 million in the first half of 1999 compared to a net gain of
$17 million in the comparable prior year period. The difference is due primarily
to a $6 million loss related to the anticipated disposition of certain
international assets in the first half of 1999 compared to a $27 million gain on
sale of certain South Texas properties, partially offset by a $14 million
provision for loss on certain physical natural gas contracts in the first half
of 1998.
Operating expenses of $340 million for the first half of 1999 were
approximately $28 million higher than the comparable period in 1998. DD&A
increased approximately $26 million compared to the prior year period, primarily
reflecting a non-recurring charge of $7.8 million recorded pursuant to a change
in strategy related to the pursuit of certain offshore operations by the
Company, increased worldwide production volumes and a higher per-unit rate in
North America. G&A was $18 million higher than the prior year period primarily
due to expanded operations, settlement of certain commercial disputes with third
parties and non-recurring costs of $8.9 million related to the potential sale
of the Company and personnel expenses. Exploration and dry hole costs were $15
million lower than the first half of 1998 primarily due to decreased exploratory
drilling and other exploration activities and improved success on wildcat
drilling prospects. Taxes other than income were down $2 million primarily due
to lower state severance taxes associated with decreased wellhead revenues in
the United States.
The per unit operating costs of the Company for lease and well, DD&A, G&A,
interest expense and taxes other than income averaged $1.55 per Mcfe during the
first half of 1999 compared to $1.42 per Mcfe in 1998. This increase is
primarily due to a higher per unit rate of G&A, interest and DD&A expenses,
partially offset by a lower per unit rate of lease and well expense and taxes
other than income. Excluding the previously mentioned non-recurring charges of
$7.8 million in DD&A and $8.9 million in G&A, the per unit operating costs for
the Company were $1.47 per Mcfe in the first half of 1999.
Interest expense, net increased $10 million as compared to the first half
of 1998 reflecting a higher level of long-term debt due to expanded worldwide
operations and decreased cash flows resulting from the above mentioned decrease
in wellhead prices.
Other income (expense), net for the first half of 1999 included a $59.6
million pre-tax gain on the sale of 3.2 million options owned by the Company
to purchase Enron Corp. common stock (See Note 9 to the Consolidated Financial
Statements).
-13-
<PAGE> 14
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
Income tax provision of $9.6 million for the first half of 1999 decreased
$0.5 million as compared to the prior year period. The decrease in income taxes
was primarily due to the lower pre-tax income partially offset by approximately
$8.4 million in tax benefits in the first half of 1998 related to certain
international costs and resolution of certain state and international issues as
compared to only $4.4 million in 1999 benefits related to the anticipated
disposition of certain international assets.
Federal income taxes accrued in the six-month interim periods are
calculated using the estimated annual effective income tax rate.
CAPITAL RESOURCES AND LIQUIDITY
The Company's primary sources of cash during the six months ended June 30,
1999 included funds generated from operations, proceeds from the sale of its
options to purchase Enron Corp. common stock and proceeds from new borrowings.
Primary cash outflows included funds used in operations, exploration and
development expenditures, dividends paid to Company shareholders and the
repayment of debt.
Net operating cash flows of $155 million for the first half of 1999
decreased approximately $39 million as compared to the first half of 1998
primarily reflecting lower operating revenues, higher interest expense and
higher cash operating expenses, partially offset by the termination of the
volumetric production payment in December of 1998.
Net investing cash outflows of approximately $141 million for the first
half of 1999 decreased by $140 million versus the comparable prior year period
due primarily to reduced exploration and development expenditures and proceeds
related to the sale of its options to purchase Enron Corp. common stock,
partially offset by lower proceeds from sales of reserves and related assets.
Changes in Components of Working Capital Associated with Investing Activities
included changes in accounts payable associated with the accrual of exploration
and development expenditures and changes in inventories which represent
materials and equipment used in drilling and related activities.
Exploration and development expenditures for the first six months of 1999
and 1998 are as follows (in millions):
<TABLE>
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
United States $160 $244
Canada 19 19
---- ----
North America 179 263
Trinidad 2 13
India (1) 19 25
China (1) 6 2
Other 3 12
---- ----
TOTAL $209 $315
==== ====
</TABLE>
- -----------------
(1) See Note 10 to the Consolidated Financial Statements.
Exploration and development expenditures of $209 million for the first half
of 1999 were $106 million lower than the prior year period due primarily to a
reduced level of service industry costs as well as reduced spending on the North
America, Trinidad and India drilling programs. Reduced drilling expenditures
were partially offset by the acquisition of producing properties in the Big
Piney area.
The level of exploration and development expenditures will vary in future
periods depending on energy market conditions and other related economic
factors. The Company has significant flexibility with respect to financing
alternatives and the ability to adjust its exploration and development
expenditure budget as circumstances warrant. There are no material continuing
commitments associated with expenditure plans.
Cash used by financing activities was $9 million for the first half of
1999 versus a cash inflow of $91 million for the comparable prior year period.
Financing activities for 1999 included the net repayment of $3 million of
long-term debt and dividend payments of $9 million, partially offset by proceeds
of $3 million from the exercise of stock options. There were no share
repurchases in the first half of 1999, compared to $8 million of repurchases in
the prior year period. Based upon existing economic and market conditions,
management believes net operating cash flow and available financing alternatives
will be sufficient to fund net investing and other cash requirements of the
Company for the foreseeable future.
-14-
<PAGE> 15
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
As disclosed in Note 10 to the Consolidated Financial Statements, the
Company and Enron Corp. have entered into an agreement relating to a Share
Exchange which requires, among other things, that the Company make indirectly a
$600 million cash capital contribution to EOG-India, Inc. prior to the closing
of the Share Exchange. As mentioned in that Note, the Company has filed a
registration statement for the public offering of 27 million shares of its
common stock (the "Offering"). As also discussed in that Note, the Company has
executed a series of new credit agreements aggregating $1.3 billion (the "Credit
Facilities"). If the Company completes the Share Exchange prior to closing the
Offering, it will use funds borrowed under the Credit Facilities for the cash
capital contribution and subsequently repay a portion of those borrowed funds
with the net proceeds of the Offering. If the Company completes the Offering on
the same day as the Share Exchange, it will use the proceeds of the Offering to
pay a significant portion of the cash capital contribution in connection with
the Share Exchange and will borrow the balance of funds needed for the Share
Exchange under the Credit Facilities. If the Company is unable to complete the
Offering at the time of or reasonably contemporaneously with the Share Exchange,
the Company will experience increased interest costs associated with the
borrowing of funds necessary to fund the cash capital contribution prior to
closing the Share Exchange until the Offering can be completed. However, the
Company has the capacity under the Credit Facilities to fund the cash capital
contribution for a one-year term and, under current market conditions, has the
ability to refinance the indebtedness. The Company also expects to maintain a
strong ability to service the interest burden of this additional financing.
As a result of the change to the Company's portfolio of assets subsequent
to the Share Exchange, the Company is currently re-evaluating its overall
business. The Company expects to complete this re-evaluation by the end of third
quarter 1999. As a result of this re-evaluation, some of the Company's current
projects may no longer be deemed central to its business. In that case, the
Company may incur non-cash charges in connection with the disposition of such
projects of up to approximately $75 million, after-tax.
YEAR 2000
The Year 2000 problem generally results from the use in computer hardware
and software of two digits rather than four digits to define the applicable
year. When computer systems must process dates both before and after January 1,
2000, two-digit year "fields" may create processing ambiguities that can cause
errors and system failures. For example, a date represented by "00" may be
interpreted as referring to the year 1900, instead of 2000.
The effects of the Year 2000 problem can be exacerbated by the
interdependence of computer and telecommunications systems in the United States
and throughout the world. This interdependence can affect the Company and its
suppliers, trading partners, and customers, as well as governments of countries
around the world where the Company does business.
State of Readiness
The Company Board of Directors has been briefed about the Year 2000
problem. The Board has adopted a Year 2000 Project (the "Project") aimed at
preventing the Company's mission-critical functions from being impaired due to
the Year 2000 problem. "Mission-critical" functions are those critical functions
whose loss would cause an immediate stoppage of or significant impairment to
core business processes (a core business process is one of material importance
to the Company business).
Implementation of the Project is directly supervised by a Year 2000
Oversight Committee, made up of four senior executives of the Company and its
affiliates. Each operating division of the Company is implementing procedures
specific to it that are part of the overall Project. The Company also has
engaged certain outside consultants, technicians and other external resources to
aid in formulating and implementing the Project.
The Company is actively implementing the Project, which will be modified
as events warrant. Under the Project, the Company will continue to inventory
mission-critical computer hardware and software systems and embedded
microprocessors (microprocessors with date-related functions, contained in a
wide variety of devices), and software; assess the effects of Year 2000 problems
on the mission-critical functions of the Company; remedy systems, software and
embedded microprocessors in an effort to avoid material disruptions or other
material adverse effects on mission-critical functions, processes and systems;
verify and test the mission-critical systems to which remediation efforts have
been applied; and attempt to mitigate those mission-critical aspects of the Year
2000 problem that are not remediated by January 1, 2000, including the
development of contingency plans to cope with the mission-critical consequences
of Year 2000 problems that have not been identified or remediated by that date.
-15-
<PAGE> 16
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
The Project recognizes that the computer, telecommunications, and other
systems ("Outside Systems") of outside entities ("Outside Entities") have the
potential for major, mission-critical, adverse effects on the conduct of Company
business. The Company does not have control of these Outside Entities or Outside
Systems. (In some cases, Outside Entities are U.S., state and local governmental
organizations, foreign governments or businesses located in foreign countries.)
However, the Project includes an ongoing process of identifying and contacting
Outside Entities whose systems in the Company's judgment have, or may have, a
substantial effect on the Company's ability to continue to conduct the
mission-critical aspects of Company business without disruption from Year 2000
problems. The Project envisions the Company making an attempt to inventory and
assess the extent to which these Outside Systems may not be "Year 2000 ready" or
"Year 2000 compatible". The Company will attempt reasonably to coordinate with
these Outside Entities in an ongoing effort to obtain assurance that the Outside
Systems that are mission-critical will be Year 2000 compatible well before
January 1, 2000. Consequently, the Company will work with Outside Entities in a
reasonable attempt to inventory, assess, analyze, convert (where necessary),
test, and develop contingency plans for connections to these mission-critical
Outside Systems and to ascertain the extent to which they are, or can be made to
be, Year 2000 ready and compatible with the Company's remediation of its own
mission-critical systems.
As of July 15, 1999, the Company is at various stages in implementation of
the Project, as shown in the following tables. Any notation of "complete"
conveys the fact only that the initial iteration of this phase has been
substantially completed. All dates are only relevant for the initial iteration
of the applicable stage of the Project.
YEAR 2000 PROJECT READINESS
<TABLE>
<CAPTION>
Inventory Assessment Analysis Conversion Testing Y2K-Ready Contingency Plan
--------- ---------- -------- ---------- ------- --------- ----------------
<S> <C> <C> <C> <C> <C> <C> <C>
Mission-Critical Internal Items C C C C IP IP IP
Mission-Critical Outside Entities C C C IP IP IP IP
Legend: C = Complete IP = In Process
</TABLE>
YEAR 2000 PROJECT ESTIMATED COMPLETION DATES
<TABLE>
<CAPTION>
Inventory Assessment Analysis Conversion Testing Y2K-Ready Contingency Plan
--------- ---------- -------- ---------- ------- --------- ----------------
<S> <C> <C> <C> <C> <C> <C> <C>
Mission-Critical Internal Items 12/98 3/99 3/99 6/99 9/99 9/99 9/99
Mission-Critical Outside Entities 3/99 6/99 6/99 9/99 9/99 9/99 9/99
</TABLE>
It is important to recognize that the processes of inventorying, assessing,
analyzing, converting (where necessary), testing, and developing contingency
plans for mission-critical items in anticipation of the Year 2000 event may be
iterative processes, requiring a repeat of some or all of these processes as the
Company learns more about the Year 2000 problem and its effects on internal
business information systems and on Outside Systems, and about the effects of
embedded microprocessors on systems and business operations. The Company
anticipates that it will continue with these processes through January 1, 2000
and on into the Year 2000 in order to assess and remediate problems that
reasonably can be identified only after the start of the new century.
The Project envisions verification and validation of certain
mission-critical facilities and functions by independent consultants. These
consultants will participate to varying degrees in many or all of the stages,
including the inventory, assessment, and testing phases. Currently, the Company
is utilizing Raytheon Engineers & Constructors, Inc. to assist Company personnel
in the inventory and assessment phases of onshore and offshore and domestic and
international operations.
Costs to Address Year 2000 Issues
The Company has not incurred material historical costs for Year 2000
awareness, inventory, assessment, analysis, conversion, testing, or contingency
planning and anticipates that any future costs for these purposes, including
those for implementing Year 2000 contingency plans, are not likely to be
material.
-16-
<PAGE> 17
Although management believes that its estimates are reasonable, there can
be no assurance, for the reasons stated in the "Summary" section below, that the
actual costs of implementing the Project will not differ materially from the
estimated costs or that the Company will not be materially adversely affected by
Year 2000 issues.
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
Year 2000 Risk Factors
Regulatory requirements. Certain of the Company's operations are regulated
by governmental authorities. The Company expects to satisfy these regulatory
authority requirements for achieving Year 2000 readiness. If the Company's
reasonable expectations in this regard are in error, and if a regulatory
authority should order the temporary cessation of operations in one or more of
these areas, the adverse effect on the Company could be material. Outside
Entities may face similar problems that materially adversely affect the Company.
Shortage of Resources. Between now and 2000 it is anticipated that there
will be increased competition for people with technical and managerial skills
necessary to deal with the Year 2000 problem. While the Company is taking
substantial precautions to recruit and retain sufficient people skilled in
dealing with the Year 2000 problem, and has hired consultants who bring
additional skilled people to deal with the Year 2000 problem, the Company could
face shortages of skilled personnel or other resources, such as particular
microprocessors or components containing Year 2000 ready microprocessors, and
these shortages might delay or otherwise impair the Company's ability to assure
that its mission-critical systems are Year 2000 ready. Outside Entities could
face similar problems that materially adversely affect the Company. The Company
believes that the possible impact of the shortage of skilled people and
resources is not, and will not be, unique to the Company.
Potential Shortcomings. The Company estimates that mission-critical
systems, domestic and international, will be Year 2000-ready substantially
before January 1, 2000. However, there is no assurance that the Project will
succeed in accomplishing its purpose, or that unforeseen circumstances will not
arise during implementation of the Project that would materially adversely
affect the Company.
Cascading Effect. The Company is taking reasonable steps to identify,
assess, and, where appropriate, to replace devices that contain embedded
microprocessors. Despite these reasonable efforts, the Company anticipates that
it will not be able to find and remediate all embedded microprocessors in all
systems. Further, it is anticipated that Outside Entities also will not be able
to find and remediate all embedded microprocessors in their systems. Some of the
embedded microprocessors that fail to operate or that produce anomalous results
may create system disruptions or failures. Some of these disruptions or failures
may spread from the systems in which they are located to other systems causing
adverse effects upon the Company's ability to maintain safe operations, to serve
its customers and otherwise to fulfill certain contractual and other legal
obligations. The embedded microprocessor problem is widely recognized as one of
the more difficult aspects of the Year 2000 problem across industries and
throughout the world. The possible adverse impact of the embedded microprocessor
problem is not, and will not be, unique to the Company.
Third parties. The Company cannot assure that suppliers upon which it
depends for essential goods and services will convert and test their
mission-critical systems and processes in a timely manner. Failure or delay by
all or some of these entities, including the U.S. and state or local governments
and foreign governments, could create substantial disruptions having a material
adverse effect on Company business.
Contingency Plans
As part of the Project, the Company is developing contingency plans that
deal with, among others, two primary aspects of the Year 2000 problem: (1) that
the Company, despite its good-faith, reasonable efforts, may not have
satisfactorily remediated all internal, mission-critical systems; and (2) that
Outside Systems may not be Year 2000 ready, despite the Company's good-faith,
reasonable efforts to work with Outside Entities. These contingency plans are
being designed to mitigate the disruptions or other adverse effects resulting
from Year 2000 incompatibilities regarding these mission-critical functions or
systems, and to facilitate the early identification and remediation of
mission-critical Year 2000 problems that first manifest themselves after January
1, 2000.
These contingency plans will contemplate an assessment of all
mission-critical internal information technology systems and internal
operational systems that use computer-based controls. This process will be
pursued continuously into the Year 2000 as
-17-
<PAGE> 18
circumstances require. Further, the Company will in that time frame assess any
mission-critical disruptions due to Year 2000-related failures that are external
to the Company.
These contingency plans include the creation, as deemed reasonably
appropriate, of teams that will be standing by on the eve of the new millennium,
prepared to respond rapidly and otherwise as necessary to mission-critical Year
2000-related problems as soon as they become known. The composition of teams
that are assigned to deal with Year 2000 problems will vary according to the
nature, mission-criticality, and location of the problem. Because the Company
operates internationally, some of its Year 2000 contingency teams will be
located at mission-critical facilities overseas.
-18-
<PAGE> 19
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
Worst Case Scenario
The Securities and Exchange Commission requires that public companies must
forecast the most reasonably likely worst case Year 2000 scenario, assuming that
the Company's Year 2000 plan is not effective. Analysis of the most reasonably
likely worst case Year 2000 scenarios the Company may face leads to
contemplation of the following possibilities which, though considered highly
unlikely, must be included in any consideration of worst cases: widespread
failure of electrical, natural gas, and similar supplies by utilities serving
the Company domestically and internationally; widespread disruption of the
services of communications common carriers domestically and internationally;
similar disruption to means and modes of transportation for the Company and its
employees, contractors, suppliers, and customers; significant disruption to the
Company's ability to gain access to, and continue working in, office buildings
and other facilities; the failure of substantial numbers of mission-critical
hardware and software computer systems, including both internal business systems
and systems (such as those with embedded microprocessors) controlling
operational facilities such as electrical generation, transmission, and
distribution systems and crude oil and natural gas plants and pipelines,
domestically and internationally; and the failure, domestically and
internationally, of Outside Systems, the effects of which would have a
cumulative material adverse impact on the Company's mission-critical systems.
Among other things, the Company could face substantial claims by customers for
loss of revenues due to supply interruptions, inability to fulfill contractual
obligations, inability to account for certain revenues or obligations or to bill
or pay customers accurately and on a timely basis, and increased expenses
associated with litigation, stabilization of operations following
mission-critical failures, and the execution of contingency plans. The Company
could also experience an inability by customers, traders, and others to pay, on
a timely basis or at all, obligations owed to the Company. Under these
circumstances, the adverse effect on the Company, and the diminution of Company
revenues, could be material, although not quantifiable at this time. Further in
this scenario, the cumulative effect of these failures could have a substantial
adverse effect on the economy, domestically and internationally. The adverse
effect on the Company, and the diminution of Company revenues, from a domestic
or global recession or depression also could be material, although not
quantifiable at this time.
The Company will continue to monitor business conditions with the aim of
assessing and quantifying material adverse effects, if any, that result or may
result from the Year 2000 problem.
Summary
The Company has a plan to deal with the Year 2000 challenge and believes
that it will be able to achieve substantial Year 2000 readiness with respect to
the mission critical systems that it controls. From a forward-looking
perspective, the extent and magnitude of the Year 2000 problem as it will affect
the Company, both before and for some period after January 1, 2000, are
difficult to predict or quantify for a number of reasons. Among these are: the
difficulty of locating "embedded" microprocessors that may be in a great variety
of mission-critical hardware used for process or flow control, environmental,
transportation, access, communications, and other systems; the difficulty of
inventorying, assessing, remediating, verifying and testing, Outside Systems
connected, and vital, to the Company's computer, telecommunications, or other
mission-critical systems; the difficulty of locating all mission-critical
software (computer code) that is not Year 2000 compatible; and the
unavailability of certain necessary internal or external resources, including
but not limited to trained hardware and software engineers, technicians, and
other personnel to perform adequate remediation, verification, and testing of
mission-critical Company systems or Outside Systems. Year 2000 costs are
difficult to estimate accurately because of unanticipated vendor delays,
technical difficulties, the impact of tests of Outside Systems, and similar
events. There can be no assurance for example that all Outside Systems with a
mission-critical impact will be adequately remediated so that they are Year 2000
ready by January 1, 2000, or by some earlier date, so as not to create a
material disruption to the Company's business. If, despite reasonable efforts
under the Year 2000 Project, there are mission-critical Year 2000-related
failures that create substantial disruptions to Company business, the adverse
impact on the Company could be material. Additionally, Year 2000 costs are
difficult to estimate accurately because of unanticipated vendor delays,
technical difficulties, the impact of tests of Outside Systems and similar
events. Moreover, despite the Company's belief that costs for implementing the
Project will not be material, the estimated costs of implementing the Project do
not take into account the costs, if any, that might be incurred as a result of
Year 2000-related failures that occur despite implementation of the Project.
-19-
<PAGE> 20
PART I. FINANCIAL INFORMATION - (CONCLUDED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONCLUDED)
ENRON OIL & GAS COMPANY
INFORMATION REGARDING FORWARD LOOKING STATEMENTS
This Quarterly Report on Form 10-Q includes forward looking statements within
the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. All statements other than statements of
historical facts, including, among others, statements regarding the Company's
future financial position, business strategy, budgets, reserve information,
projected levels of production, projected costs and plans and objectives of
management for future operations, are forward-looking statements. The Company
typically uses words such as "expect", "anticipate", "estimate", "strategy",
"intend", "plan" and "believe" or the negative of those terms or other
variations of them or by comparable terminology to identify its forward-looking
statements. In particular, statements, express or implied, concerning future
operating results or the ability to generate income or cash flows are
forward-looking statements. Although the Company believes its expectations
reflected in forward-looking statements are based on reasonable assumptions, no
assurance can be given that these expectations will be achieved. Important
factors that could cause actual results to differ materially from the
expectations reflected in the forward-looking statements include, among others:
timing and extent of changes in commodity prices for crude oil, natural gas and
related products and interest rates; extent of the Company's success in
discovering, developing, marketing and producing reserves and in acquiring oil
and gas properties; successful implementation of the Company's Year 2000
Project, the effectiveness of its Year 2000 Project, and the readiness of
outside entities; political developments around the world; and financial market
conditions.
In light of these risks, uncertainties and assumptions, the events
anticipated by the Company's forward-looking statements might not occur. The
Company undertakes no obligations to update or revise its forward-looking
statements, whether as a result of new information, future events or otherwise.
-20-
<PAGE> 21
PART II. OTHER INFORMATION
ENRON OIL & GAS COMPANY
ITEM 1. Legal Proceedings
See Part 1, Item 1, Note 7 to Consolidated Financial Statements which is
incorporated herein by reference.
ITEM 4. Submission of Matters to a Vote of Security Holders
The Annual Meeting of Shareholders of Enron Oil & Gas Company was held
on June 28, 1999, in Houston, Texas, for the purpose of electing a board of
directors, approving the Amended and Restated Enron Oil & Gas Company 1992 Stock
Plan and ratifying the appointment of auditors. Proxies for the meeting were
solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934, and
there was no solicitation in opposition to management's solicitations.
(a) Each of the directors nominated by the Board and listed in the
proxy statement was elected with votes as follows:
<TABLE>
<CAPTION>
Shares Shares
Nominee For Withheld
------- ----- --------
<S> <C> <C>
Fred C. Ackman 146,788,441 217,627
Richard A. Causey 146,325,089 680,979
James V. Derrick, Jr. 146,313,635 692,433
John H. Duncan 146,790,406 215,662
Ken L. Harrison 146,324,878 681,190
Forrest E. Hoglund 146,327,832 678,236
Kenneth L. Lay 146,329,849 676,219
Mark G. Papa 146,331,844 674,224
Edward Randall, III 146,775,374 230,694
Jeffrey K. Skilling 146,332,412 673,656
Frank G. Wisner 146,792,542 213,526
</TABLE>
(b) The Amended and Restated Enron Oil & Gas Company 1992 Stock Plan
was approved by the following vote: 129,937,604 shares for;
16,737,923 shares against; and 330,541 shares abstaining.
(c) The appointment of Arthur Andersen LLP, independent public
accountants, as auditors for the year ending December 31, 1999
was approved by the following vote: 146,849,409 shares for;
70,408 shares against; and 86,251 shares abstaining.
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges
Exhibit 27 - Financial Data Schedule
(b) Reports on Form 8-K - There were no reports on Form 8-K filed for
the quarterly period ended June 30, 1999.
-21-
<PAGE> 22
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ENRON OIL & GAS COMPANY
(Registrant)
Date: July 30, 1999 By /s/ W. C. WILSON
--------------------------------
W. C. Wilson
Senior Vice President and
Chief Financial Officer
(Principal Financial and Accounting Officer)
-22-
<PAGE> 23
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Exhibit Number Description
- -------------- -----------
<S> <C>
12 Computation of Ratio of Earnings to Fixed Charges
27 Financial Data Schedule
</TABLE>
<PAGE> 1
EXHIBIT 12
ENRON OIL & GAS COMPANY
Computation of Ratio of Earnings to Fixed Charges
(In Thousands)
(Unaudited)
<TABLE>
<CAPTION>
SIX MONTHS
ENDED JUNE 30, YEAR ENDED DECEMBER 31,
------------- -------------------------------------------------------------
1999 1998 1997 1996 1995 1994
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
EARNINGS AVAILABLE FOR
FIXED CHARGES:
Net Income $ 25,704 $ 56,171 $ 121,970 $ 140,008 $ 142,118 $ 147,998
Less: Capitalized Interest Expense (6,306) (12,711) (13,706) (9,136) (6,490) (6,124)
Add: Fixed Charges 35,347 61,290 41,423 21,997 18,414 14,613
Income Tax Provision(Benefit) 9,636 4,111 41,500 50,954 41,936 5,937
--------- --------- --------- --------- --------- ---------
EARNINGS AVAILABLE $ 64,381 $ 108,861 $ 191,187 $ 203,823 $ 195,978 $ 162,424
========= ========= ========= ========= ========= =========
FIXED CHARGES:
Interest Expense 29,041 48,463 27,369 12,370 11,310 8,135
Capitalized Interest 6,306 12,711 13,706 9,136 6,490 6,124
Rental Expense Representative of
Interest Factor -- 116 348 491 614 354
--------- --------- --------- --------- --------- ---------
TOTAL FIXED CHARGES $ 35,347 $ 61,290 $ 41,423 $ 21,997 $ 18,414 $ 14,613
========= ========= ========= ========= ========= =========
RATIO OF EARNINGS TO
FIXED CHARGES 1.82 1.78 4.62 9.27 10.64 11.12
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 11,411
<SECURITIES> 0
<RECEIVABLES> 172,264
<ALLOWANCES> 0
<INVENTORY> 35,175
<CURRENT-ASSETS> 225,270
<PP&E> 4,965,113
<DEPRECIATION> (2,298,265)
<TOTAL-ASSETS> 2,962,046
<CURRENT-LIABILITIES> 199,487
<BONDS> 0
0
0
<COMMON> 201,600
<OTHER-SE> 1,108,444
<TOTAL-LIABILITY-AND-EQUITY> 2,962,046
<SALES> 350,385
<TOTAL-REVENUES> 346,149
<CGS> 0
<TOTAL-COSTS> 340,058
<OTHER-EXPENSES> (58,290)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 29,041
<INCOME-PRETAX> 35,340
<INCOME-TAX> 9,636
<INCOME-CONTINUING> 25,704
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 25,704
<EPS-BASIC> 0.17<F1>
<EPS-DILUTED> 0.17
<FN>
<F1>Basic
</FN>
</TABLE>
